1. Field
The present invention relates to the field of enhanced hydrocarbon recovery operations. More specifically, the present invention relates to procedures for injecting water or other fluid into subsurface formations such as weak or unconsolidated formations.
2. Background
Hydrocarbon recovery processes often employ injection wells, such as water injection wells, in connection with the extraction of oil and gas from subsurface formations. One of several reasons may exist for injecting water into a formation. In some instances water injection wells are used to maintain pressure in a reservoir during production. Alternatively, water injection wells may be used to push or “sweep” in-place hydrocarbon fluids towards producing wells. Such purposes relate to enhanced oil recovery.
In some cases, water injection may be used as a means of disposing produced but unwanted water. The water is typically a salt water solution, or brine. The water may include fines or waste solids, thereby forming an aqueous slurry. In addition, the water may include residual hydrocarbon fluids, formation treatment chemicals, corrosion products and biological organisms.
The success of any water injection well depends on maintaining an appropriate injection capacity, or “injectivity,” over the planned lifetime of the development. A decline of well injectivity results in the injection of reduced volumes of water into a targeted subsurface formation. This, in turn, results in sub-optimal pressure maintenance or oil sweep to producing wells, or inadequate disposal of water into the subsurface formation.
The injectivity of a well (“II”) is defined as the ratio of the injection rate to the pressure differential between the fluid in the well bore and the “far field” reservoir pressure:
  II  =            Q      inj        /          (                        P          inj                -                  P          res                    )      wherein:                Qinj=injection rate;        Pinj=flowing bottom hole injection pressure; and        Pres=reservoir pressure.        
Various ways of monitoring the flowing bottom hole injection pressure (“FBHP”) exist. These include downhole gauges and calculating the FBHP from wellhead pressure measurements.
Several different influences can reduce the “II” of a well. For example, contaminants in the injected fluid can plug either the openings in the downhole tubulars or the pore spaces in the subsurface formation. Such contaminants may include scale, corrosion products and fines in solution. In the context of offshore operations, contaminants may also include biological organisms from seawater that pass through water filters. Changes to the rock formation itself can also reduce injectivity. Such changes may include fines migration, compaction of the rock in the near wellbore region, or gross deformation of the rock.
Build-up of reservoir pressure can also change an injection well's “II.” In this respect, if reservoir pressure decreases, then the pressure differential increases. This, in turn, reduces the value of “II” from the equation. Of course, it is noted that injection wells are typically run at a constant rate, so changes in reservoir pressure are usually offset by changes in wellhead pressure. At the same time, completion engineers will understand that an injection well design may be flawed when a well is subject to plugging such that a constant rate cannot be maintained.
The regime of operation of an injection well can also determine which of these processes may impact the “II” of an injector. Generally, there are three possible modes of operation for injection wells: (1) matrix diffusion, (2) formation fracture, and (3) formation fluidization. These regimes are discussed generally below.
(1) Matrix injection means that water is injected into the pore spaces of a rock formation at a pressure that is less than the formation fracture pressure. Matrix injection is characterized by radial Darcy flow of the injected fluid through the porous media. In some cases an enhanced matrix injection will be employed that starts with a propped fracture stimulation to delay the effects of contaminant plugging.
(2) Formation fracture injection means that the formation is fractured as a result of the injection process. This may be done through the formation of artificial fractures using one or more injection fluids under pressure, such as a proppant-based fracture fluid, water, or an aqueous solution. When the mode of injection is formation fracture, the increase in pressure from the injected fluid creates a physical parting of the rock formation. The injected fluid flows into the void created by the fracture of the rock and eventually diffuses into the pores of the rock exposed by the fracture. Preferably, the fracturing injection process extends the fractures as necessary to maintain a desired injection rate. In addition, the newly opened fracture faces provide for increased surface area as needed to maintain the injection rate.
(3) The formation fluidization mode of injector operation occurs when stress created in the subsurface formation by the injection operation causes inelastic deformation of the porous media within the subsurface formation in a region beyond the crack tip. When the mechanical deformation of the formation during injection is not governed by linear elastic fracture mechanics (“LEFM”), the formation does not “fracture” in the classical sense. Fracture processes therefore cannot be modeled using LEFM theory. In practice, the injection pressure continues to rise, but the formation does not receive more water. It is noted that LEFM assumes that plastic deformation is limited to an infinitely small region at the tip. In the formation fluidization mode, the formation is such that the plastic zone is much more extensive. The formation goes through a failure process rather than forming a discrete fracture. As a result, the Pinj value continues to increase after material failure occurs as opposed to brittle LEFM fractures which have a defined fracture extension pressure based on formation mechanical properties, the in-situ stress field and other related variables.
A decline in a well's injectivity (“II”) results in the injection of reduced volumes of water into the target subsurface formation. In the case of enhanced recovery operations, this results in sub-optimal pressure maintenance or oil sweep to producing wells. This, in turn, can negatively impact a field's hydrocarbon recovery processes. In the case of simple water disposal, a decline in well injectivity results in an inadequate disposal of water/liquid wastes into the subsurface formation or injection pressures that may risk a loss of containment.
Correlations can generally be made concerning the effect of geomechanical forces on injectivity. If a targeted subsurface formation can be mechanically characterized as a low compressibility, stiff, and strong shear strength rock, then as injectivity decreases, the increase in operating injection pressure is typically overcome via fracturing of the targeted rock formation. This fracturing phenomenon often results in a stabilization of the well's injectivity, thereby providing a relatively constant injection pressure at a constant rate of water injection.
On the other hand, if a targeted subsurface formation can be mechanically characterized as a highly compressible, uncemented, weak-shear-strength rock, then a loss of injectivity can occur, particularly at high water injection rates. This is a result of several factors such as near-wellbore rock and/or sand fluidization and the creation of rock fines that plug pore spaces. The presence of injected particulate matter can also plug the near-wellbore matrix. The low strength and high compressibility of the rock formation minimizes the chance that a fracture will form or propagate into the rock formation. Without the “clean” rock surface exposed by a propagating fracture, the “II” of the well can decline rapidly.
Formations having a weak shear strength or having characteristics of being compressible and unconsolidated are located in various fields around the world. Examples include developments in West Africa, Gulf of Mexico, Chad, and Sakhalin (an island off the coast of mainland Russia and just north of Japan). In such developments it is a challenge to maintain injection capacity and reliability of water injection wells.
Therefore, it is desirable to have a method for designing and operating fluid injectors in highly compressible, weakly-cemented, weak-shear-strength rock formations that avoids the loss of injectivity seen in such wells.